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Continued improvements to our balance sheet, continued improvements to our industry-leading operational efficiencies and cost control, continued execution of strategic disciplined long-term approach to mergers and acquisitions that are accretive and will add to operating profits and fuel balance growth. And, fourth, the final one, continued modification to our completion design and techniques, specifically formulated to enhance our large continuous Southern Midland Basin acreage position, which is largely HBP. I'm pleased to report, we were successful in all four strategic elements during the past year. During the year, we successfully reduce long-term debt by 127.1 million and eliminated approximately 30 million, 35 million in future interest expense; extended our credit agreement maturity date to May of 2020 realized 11.4 million increase in operating cash flow representing a 44% increase, realized 7% decrease in LOE year-over-year with a record low of $4.23 per BOE, operating cost.During the year, we drilled 13 completed nine horizontal wells, with an average completing well cost of roughly 4.3 million for an outside well.

CAPEX for full-year total 47.1 million and included 44.2 million for drilling and completion activities funded primarily through cash flow. Total production for the year of 4.2 million BOE is representing 11.6 MBOEs per day exceed the mid-point of our annual guidance. Our 2017 year proved reserves increased to 181.5 million BOEs representing a 16% year-over-year increase. In addition, we officially increased our company's type curve to 700 MBOEs per well representing a 37% improvement from our previous published type curve.

Lastly, at the end of the year, we closed on an accretive bolt-on acquisition funded by equity, which significantly expanded our acreage footprint in the highest oil concentration in the US. If we recall, I mentioned over the last several years we have implemented a consistent strategy for managing through the cycle, the strategy focused on corporate level returns in the face of continued volatile commodity price, we delivered a third consecutive year of fiscal discipline, optimizing returns, and providing steady production output. Our forethought regarding the benefit of instruction and our continued emphasis on cost control, operating efficiencies, delivered industry-leading operating expense. Despite double-digit service costs, escalation across the Permian basin, even with weather-related operational restrictions during the year Hurricane Harvey, we delivered solved production about the midpoint of annual guidance.

Turning to Slide 5 in the presentation, we are raising our type curve as I stated to 700 MBOEs comprised to roughly 30% all, 33% NGLs, 37% Natural gas. As you may recall, in our earlier discussions during the year, in early 2015 we began modifying our completion designs, tighter stage spacing increase in profit loading and profit mix and improved fluid chemistries including a recycle base fluids, specialized chemicals and compounds with a focus on increasing affective SRV by minimizing formation damage and post-frack fine migration issues. As the year ended in 2017, we had successfully implemented design changes on 36 Wolfcamp A, B, and C wells. The cumulative results of these enhancements is an average EUR per well of 700 MBOEs representing 37% improvement over our previous type curves.

Turning to Slide 6, during 2017 we brought nine wells on and those nine wells are tracking, as you can see the 700 MBOE type curve. When looking at the slide you will notice the two wells performing, one slightly below the curve and one considerably below the curve are both extended reach laterals. The tree wells significantly outperforming the type curve were science wells utilizing specialized chemicals and compounds.

On Slide 7, you will see our asset base is unique due to the flat PDP decline, and consequentially the low capital intensity required to maintain our production base. Our prior strategic investment instruction in our continuous operational efficiency improvements return repeatable, immediate cost benefits for approach and potentially long-term recovery benefits. Our 2018 strategic objectives, unchanged, remain focused on execution and cost structure while evaluating synergistic acquisition opportunities that further strengthen our balance sheet and are accretive to per share metrics. Our capital program will be focused near infrastructures to maximize inherent value of our assets and we will align as closely as possible within cash flow.

We have established our preliminary capital budget funded primarily from operating cash flow of $50 million to $70 million. This is highly dependent on realized commodity pricing and oil-field service cost escalations. We have provided annual first-quarter guidance on Slide 17, which forecast 2018 production growth of approximately 2% year-over-year.

With that, I'll turn the call to Qingming Yang to review operational highlights, Sergei to review financial highlights, and then I'll wrap up before Q&A.

Qingming Yang -- President, Chief Operating Officer

Thanks, Ross, and good morning everyone. I will start with Slide 9 and provide a summary of operating activities and results for the fourth-quarter and full-year 2017. We drilled 1 horizontal well in the fourth quarter in Pangea West and produced 11.6000 BOE per day. During 2017, we drilled 13 and completed nine wells and produced 11.6000 BOE per day, about the midpoint of our annual guidance with a capital budget below the lower end of our annual guidance.

In the year-end 2017, we had ten horizontal wells waiting on completion. We currently have four wells in flowback and I'm very encouraged by the early results of these wells. We look forward to sharing more details on the results of this wells on the first quarter earnings call. On the operational front, we continue to optimize our completion design, surface facilities and increase our operating efficiencies.

Our prior investment in infrastructures continues to provide meaningful benefits to our cost structure.

Turning to Slide 10, during the year, we achieved annual record-low lease operating expense of $4.23 per BOE, despite double-digit service cost escalation across the Permian basin as Ross mentioned earlier. As an example, our cost for handling produced water is down 54% from 2015 now at $0.87 per barrel. Recently, we have traded produced water for fracking at approximately $0.42 per barrel down 71% from an already low cost of $1.40 to $1.80 per barrel established in 2015.

On Slide 11, you will see the benefit of our drilling and completion costs as well. We maintained our industry-leading drilling and completion cost of $4.3 million per well, while successfully managing our natural production decline.

Slide 12 highlights our year-end 2017 proved reserves 21 totaling 181.5 million BOE offering a balanced portfolio mix of 28% oil, 32% NGLs and 40% natural gas. Extensions and discoveries for 2017 were 33.3 million BOE, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 million BOE of proved reserves through bolt-on acquisition, and we classified 17.7 million BOE of proved undeveloped reserves that are not expected to be developed within five years under SEC rules into probable reserves. Revisions during 2017 included an increase of 9.4 million BOE resulting from improved well performance and technical parameters and an increase of 3.1 million BOE due to higher commodity prices.

Our PV-10 for proved reserves at year-end 2017 using SEC prices were $521 million untapped or 69% increase from year-end 2016. Our PV-10 for proved reserves at year-end 2017 was 582.2 million used December 31, 2017, NYMEX Street prices. Our reserve replacement ratio was 748%.

Now I'll turn the call over to our CFO Sergei Krylov, who will review our financial results.

Sergei Krylov -- Chief Financial Officer

Thanks, Qingming. On Slide 9 we have summarized our financial results for fourth-quarter and full-year 2017. The highlights for this quarter are higher revenue, unhedged cash margin, an extension of the maturity date of our credit facility and reaffirmation of our $325 million borrowing base. One of the benefits of our assets is the balanced commodity portfolio.

On Slides 13 and 14 you see that the approach is benefiting from commodity price appreciation across all product streams. In 2017, we realized that 43% year-over-year improvement in unhedged cash margin. Revenue for the quarter was 28.4 million, up 11% over prior quarter. Fourth quarter EBITDAX flowed 13.9 million.

Net income for fourth-quarter was 45.8 million or $0.51 per diluted share. Net income included an income tax benefit of 51.9 million related to the reduction in our deferred tax liabilities, resulting from the Tax Cuts and Jobs Act and an increase in the fair value of our commodity revenues. On an adjusted basis, our net loss totaled 6.1 million or $0.07 per diluted share. Fourth quarter lease operating expense was $4.77 per BOE, primarily attributed to colder seasonal weather and an increase in work hours.

Production and valorem taxes averaged $2.09 per BOE and represented 7.8% of oil, NGL and gas sales. Exploration Operation costs were $0.38 per BOE. Total general and administrative costs averaged $5.16 per BOE, including cash G&A costs of $4.09 per BOE. Depreciation and amortization expense averaged $15.20 per BOE and interest expense totaled $5.4 million.

In 2017, operating cash flow increased by 44% over the prior year to $37.5 million. Primarily using cash flow generated from operations, capital expenditures for the year totaled $47.1 million and included $44.2 million for drilling and completion activities. Delivering on our key initiatives for the year, we continue to improve our financial flexibility and strengthened our balance sheet for the large-scale recapitalization and accretive asset purchase. These transactions reduced the outstanding principles of our long-term debt by $145 million.

Turning to Slide 15, on December 31, 2017, we had a $1 billion senior secured revolving credit facility with a $325 million borrowing base and commitment amount. At December 31, 2007, our liquidity totaled approximately $33.7 million and we were in compliance with all covenants. We have no near-term debt maturities.

On Slide 16, highlights, you'll see our hedge book for 2018 that now covers approximately 52% of forecasted oil, 55% of 2018 forecasted natural gas, and 50% of our NGL production based on the midpoint of guidance.

Turning to Slide 17, you will find our annual production and expense guidance for 2018 and we expect fourth quarter production of 11,300 BOE per day, except in preliminary capital budget for the year funded from operating cash flow of $50 million to $70 million. With this budget, we expect to resume year-over-year production growth. During 2018, we will continue to focus on living within cash flow, however, the budget is highly flexible and allows us to make adjustments depending on the direction of commodity prices.

Now I will turn the call back to Ross.

Thanks, Sergei. Approach has a long history of operating in Midland Basin. With 186 horizontal Wolfcamp wells online at year-end, we continue to demonstrate the resilience of our assets, the suitability for manufacturing style development and proficiency of our team. The history we have with our asset base gives us a robust understanding of how to extract value.

Looking forward, we see opportunities to continue consolidating Southern Midland Basin assets, exporting our existing infrastructures and deploying our industry-leading execution and cost structure to create additional value for our shareholders.

With that, we'll open it up for Q&A.

Questons and Answers:

Operator

Thank you. I'll now open the lines for your questions. [Operator Instructions]. Our first question comes from the line of Irene Haas of Imperial Capital.

Your line is open.

Irene Haas -- Imperial Capital

Great. So good morning, everybody. My question has to do with sort of fourth-quarter production mix seems to be too less oily than we have anticipated. And then when we kind of look at your forward guidance for 2018, it appears that you resume a higher oil mix.

Is there something unusual about operations during the fourth quarter?

Ross Craft -- Chief Executive Officer, Chairman

Yes, if you look at the-Irene, good question. If you look at the fourth quarter, we didn't bring any new completions on during the fourth quarter. We had-we were in the process of fracking some wells that we had several wells shut in for frack operations. And then, obviously, we still had some winterized whether that came in at the end, which drove some numbers.

But those were all just a temporary type environment based on activities at the time and typical winter-type environment.

Irene Haas -- Imperial Capital

So the same reasoning will go toward yours year-end. So proved reserves oil mix also, a little light that you probably expect to catch up by next year?

Ross Craft -- Chief Executive Officer, Chairman

I think, looking at the source oil reserve, it's really a reflection of a continued sort of shallow decline of gas. So if you look at the-our wells, and the gas reserves and NGL reserves have improved significantly and then oil reserves sort of state where they are. So as a result, the percentage of the oil over the total unit BOE recoverable is less than what it was before.

Irene Haas -- Imperial Capital

Okay, that makes sense. Thank you.

Operator

Thank you. [Operator Instructions]. And we do have a question from the line of Gail Nicholson of KRL Group. Your line is open.

Gail Nicholson -- KLR Group

Good morning. I was just looking at the 2018 budget and the plans. Are you planning to use the specialty chemicals and nano-particles in the 2018 wells, or kind of what's the thought there? And then how should we think about well cost if we utilize those in the 2018 timeframe?

Ross Craft -- Chief Executive Officer, Chairman

Yes, we'll continue to modify and develop new compounds, that's what we're working on right now. It's not using existing compounds, it's developing our own new compounds. Obviously right now, we are in a very extensive testing program on some of these compounds. Now to get to what it does impact as far as cost basis, I think what you'll see is, if we go this route, which most likely as we continue to define this, we most likely will, that you're probably going to see for the specialty chemicals probably $300,000 to $400,000 per well increase in cost.

So from that standpoint that's kind of what it does. Now what we haven't done yet is starting to-which is part of what we're studying is starting to look at what other chemicals which are normally pumped in shale wells are going to be able to be eliminated completely, which we think that the bulk of the chemicals that we spend a lot of money on will probably be able to be either greatly reduced or completely eliminated by using some of these compounds, which will drive the price back down. But at this point, I don't have a number on that yet.

Gail Nicholson -- KLR Group

Okay, great. And then just looking at, where the current decline rate is and looking at the budget between $50 million and 70 million this year and looking at the production guide, is it fair to assume that is it roughly $50 million keeps production relatively flat on a year-over-year basis, or with the weather in 1Q that maintenance CAPEX is actually below $50 million?

Ross Craft -- Chief Executive Officer, Chairman

No, I think, you'd be safe to assume that the $50 million will be the-we will be able to maintain production base like it is and hopefully, with the continuation of these well results, possibly grow it.

Gail Nicholson -- KLR Group

Okay, great. Thank you.

Operator

Thank you. And our next question is from the line of Irene Haas from Imperial Capital. Your line is open.

Irene Haas -- Imperial Capital

Yes, I have two follow-up questions. One has to do with the longer laterals that you guys tried out last years since it's sort of underperforming. Is that-does it mean that you guys are probably going to stick standard laterals? That's my first question.

Ross Craft -- Chief Executive Officer, Chairman

Yes, I think, this is not anything surprising. I think we're starting to see evidence throughout the Basin that when you at drilling extended-reach laterals, you do it for two reasons. You do it either to improve per 1,000-foot recoverables or you're doing it to improve your economics based on cost. So we drilled six extended-reach laterals over the last two years, I believe, average drilled lengths of those laterals were like 9,600 feet.

So when you look at these extended-reach laterals as plotted on these plots that we supply, remember, these are all normalized back down to a 7,500-foot lateral. So you're taking a lateral that's much longer, normalizing it down, which brings everything down to try to get a true cost interpretation and performance interpretation. We do not see a lot of benefits, if any, for longer laterals in our particular area. In fact, what we're focusing on right now is streamline our laterals to match the type of chemicals we're pumping and match the type of reservoir we have.

I doubt, unless there's a specific instance out there, we're trying to hold something that we will pursue any extended-reach laterals in 2018.

Irene Haas -- Imperial Capital

Okay, that's fair. My second question is really for Sergei. You mentioned earlier that you will spend within cash flow, which we understand. You also, mentioned that you will be flexible.

So I'm just curious, if oil indeed takeoff, again, how fast would you be able to react and ramp-up? And also, what is the rig count precisely for 2018? Is it part of one rig?

Ross Craft -- Chief Executive Officer, Chairman

Yes, so the rig count for 2018 is a part-time rig, so we will run intermittently. In terms of capital budget, as mentioned, the range is $50 million to $70 million. And the range-even the high-end of the range contemplates some additional commodity price recovery. We, as you know, we operate 100% of our asset base.

So we have the ability to ramp capital up and down as we see fit. We don't have any lease expirations of sites that we need to worry about. So our ability to ramp up really will be driven by operational service availability and access to services if you want to move faster.

Irene Haas -- Imperial Capital

Yes. So how fast is fast? Can you do it within a three months period, I'm just curious?

Qingming Yang -- President, Chief Operating Officer

Irene, what we have found is, obviously, the cost has escalated over the last couple of years because of the demand in Permian Basin, especially in Permian Basin. But we do find that the rigs are still available, the fracking crews are still available and the service is still available. The only concern over there is rainy sort of in the cost. If we have to react to increasing oil price and try to sort of react to that and there might be sort of a cost increase over there.

But as far as what we know right now, all those surveys are available.

Irene Haas -- Imperial Capital

Okay, that's great. I guess, you guys-the rigs you use are not the really expensive ones. So I suppose there's more availability out there?

Qingming Yang -- President, Chief Operating Officer

That's right. As you know, in our areas, this is kind of a space where we can use those in 1000 horsepower to drill those, 7,500 freight laterals. And those rigs may not be able to be utilized in some of the different parts of the basin. So in a way, we're a little bit unique because we are in a shallower part of the basin.

Irene Haas -- Imperial Capital

Great. Thank you.

Qingming Yang -- President, Chief Operating Officer

Thanks, Irene.

Operator

Thank you. At this time, there are no further questions. I'd like to turn the conference over to Mr. Ross Craft for closing remarks.

Ross Craft -- Chief Executive Officer, Chairman

Yes, we appreciate everybody's interest in the company. Obviously, this has been a challenging time for everyone for the last three years. But we continue to focus on improvements in recoveries, improvements in cost structure, and improvements in the balance sheet, and I think we've done an outstanding job and we'll continue to do an outstanding job going forward. With that, we appreciate your time and look forward to talking to you next quarter.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.

Duration: 31 minutes

Call Participants:

Suzanne Ogle -- Vice President, Investor Relations and Corporate Communications

Ross Craft -- Chief Executive Officer, Chairman

Qingming Yang -- President, Chief Operating Officer

Sergei Krylov -- Chief Financial Officer

Irene Haas -- Imperial Capital

Gail Nicholson -- KLR Group

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